EP1937391A1

EP1937391A1 - Sulfur trioxide removal from a flue gas stream

Info

Publication number: EP1937391A1
Application number: EP06793512A
Authority: EP
Inventors: John Maziuk; Rasik Raythatha
Original assignee: Solvay Chemicals Inc
Current assignee: Solvay Chemicals Inc
Priority date: 2005-09-15
Filing date: 2006-09-14
Publication date: 2008-07-02
Also published as: WO2007031552A1; CA2622549A1; CN101262929A; JP2009507632A; BRPI0616068A2; CN101262929B; EA015416B1; EA200800829A1; CA2622549C

Abstract

A method of removing SO3 from a flue gas stream having increased amounts of SO3 formed by a NOx removal system, includes injecting a sorbent composition into the flue gas stream. The sorbent composition includes an additive and a sodium sorbent such as mechanically refined trona or sodium bicarbonate. The additive is selected magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The concentration of the SO3 in the flue gas stream is reduced and the formation of a liquid phase NaHSO4 reaction product is minimized.

Description

Sulfur trioxide removal from a flue gas stream

The present invention relates to the purification of gases, and more particularly to a method of purifying flue gases which contain noxious gases such as SO₃. SO3 is a noxious gas that is produced from the combustion of sulfur- containing fuel. When present in flue gas, the SO₃ can form an acid mist that condenses in electrostatic precipitators, ducts or bag houses, causing corrosion. SO3 at concentrations as low as 5-10 ppmin exhaust gas can also result in white, blue, purple, or black plumes from the cooling of the hot stack gas in the cooler air in the atmosphere.

The effort to reduce NO_x emissions from coal- fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SO₂ to SO3 and thereby increasing total SO3 emissions. SCRs employ a catalyst (typically vanadium pentoxide) to convert NO_x to N₂ and H₂O with the addition of NH3, but there is also an unintended oxidation of the SO₂ to SO3. Although the higher stack SO3 concentrations are still relatively low, the emissions can sometimes produce a highly visible secondary plume, which, although unregulated, is nonetheless perceived by many to be problematic. Efforts to reduce the SO3 levels to a point where no secondary SO3 plume is visible can impede particulate collection for stations that employ electrostatic precipitators (ESPs). SO3 in the flue gas absorbs onto the fly ash particles and lowers fly ash resistivity, thereby enabling the ESP to capture the particle by electrostatic means. Many plants actually inject SO₃ to lower fly ash resistivity when ash resistivity is too high. SO3 reacts with water vapor in the flue gas ducts of the coal power plant and forms vaporous H2SO4. A portion of this condenses out in the air heater baskets. Another portion of the sulfuric acid vapor can condense in the duct if the duct temperature is too low, thereby corroding the duct. The remaining acid vapor condenses either when the plume is quenched when it contacts the relatively cold atmosphere or when wet scrubbers are employed for flue gas desulfurization (FGD), in the scrubber's quench zone. The rapid quenching of the acid vapor in the FGD tower results in a fine acid mist. The droplets are often too fine to be absorbed in the FGD tower or to be captured in the mist eliminator. Thus, there is only limited SO₃ removal by the FGD towers. If the sulfuric acid levels emitted from the stack are high enough, a secondary plume appears.

Dry sorbent injection (DSI) has been used with a variety of sorbents to remove SO3 and other gases from flue gas. However, DSI has typically been done in the past at temperatures lower than around 370° F because equipment material, such as baghouse media, cannot withstand higher temperatures. Additionally, many sorbent materials sinter or melt at temperatures greater than around 400° F, which makes them less effective at removing gases. Another problem is that under certain temperature and gas concentration conditions the reaction products of many sorbent materials adhere to equipment and ducts, which requires frequent cleaning of the process equipment.

In one aspect, a method of removing SO₃ from a flue gas stream having increased amounts Of SO₃ formed by a NO_x removal system, includes injecting a sorbent composition into the flue gas stream. The sorbent composition includes an additive and a sodium sorbent such as mechanically refined trona or sodium bicarbonate. The additive is selected magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The concentration of the SO3 in the flue gas stream is reduced and the formation of a liquid phase NaHSO₄ reaction product is minimized.

In another aspect, a method of delivering a dry sorbent for flue gas injection includes providing trona. A sorbent composition is formed by combining with the trona an additive selected from magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream. Sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel. The foregoing paragraphs have been provided by way of general introduction, and are not intended to limit the scope of the following claims. The presently preferred embodiments, together with further advantages, will be best understood by reference to the following detailed description taken in conjunction with the accompanying drawings. FIG. 1 is a phase diagram showing the reaction products of trona with SO₃ as a function of flue gas temperature and SO3 concentration. FIG. 2 is a schematic of one embodiment of a flue gas desulfurization system.

The invention is described with reference to the drawings in which like elements are referred to by like numerals. The relationship and functioning of the various elements of this invention are better understood by the following detailed description. However, the embodiments of this invention as described below are by way of example only, and the invention is not limited to the embodiments illustrated in the drawings.

Dry sorbent injection (DSI) has been used as a low cost alternative to a spray dry or wet scrubbing system for the removal of SO₃. In the DSI process, the sorbent is stored and injected dry into the flue duct where it reacts with the acid gas. Under certain processing conditions, the reaction product of the sorbent and the acid gas is a sticky ash. The sticky ash tends to stick to the process equipment and ducts, thus requiring frequent cleaning. Thus, it would be beneficial to have a process that minimizes the amount of sticky ash reaction product.

A particular sorbent that may be used in SO₃ removal is trona. Trona is a mineral that contains about 85-95% sodium sesquicarbonate (Na₂CO₃-NaHCO₃^H₂O). A vast deposit of mineral trona is found in southwestern Wyoming near Green River. As used herein, the term "trona" includes other sources of sodium sesquicarbonate. Another sorbent that may be used is sodium bicarbonate. The term "flue gas" includes the exhaust gas from any sort of combustion process (including coal, oil, natural gas, etc.). Flue gas typically includes acid gases such as SO₂, HCl, SO₃, and NO_x. When heated at or above 275°F, sodium sesquicarbonate undergoes rapid calcination of contained sodium bicarbonate to sodium carbonate, as shown in the following reaction:

2 [ Na₂CO₃ • NaHCO₃ • 2H₂O] → 3Na₂CO₃ + 5H₂O + CO₂ A preferred chemical reaction of the sorbent composition with the SO₃ is represented below:

Na₂CO₃ + SO₃ → Na₂SO₄ + CO₂

However, under certain conditions, undesirable reactions may occur which produce sodium bisulfate. If the sodium sesquicarbonate is not completely calcined before reaction with SO₃, the following reaction occurs: NaHCO₃ + SO₃ → NaHSO₄ + SO₃ Under certain conditions, another undesirable reaction produces sodium bisulfate as represented below:

Na₂CO₃ + SO₃ + H₂SO₄ → 2NaHSO₄ + CO₂

Sodium bisulfate is an acid salt with a low melt temperature and is unstable at high temperatures, decomposing as indicated in the following reaction:

2NaHSO₄ → Na₂S₂O₇

The type of reaction product of the Na₂CO₃ and the SO₃ depends on the SO₃ concentration and the temperature of the flue gas. FIG. 1 is a phase diagram showing the typical reaction products of trona with SO₃ as a function of flue gas temperature and SO₃ concentration. In particular, above a certain SO₃ concentration, the reaction product can be solid NaHSO₄, liquid NaHSO₄, Na₂SO₄, or Na₂S₂O₇, depending on the flue gas temperature. Liquid NaHSO₄ is particularly undesirable because it is "sticky" and tends to adhere to the process equipment, and cause other particulates, such as fly ash, to also stick to the equipment. Thus, it may be desirable to operate the process under conditions where the amount of liquid NaHSO₄ reaction product is minimized. The boundary in FIG. 1 between the liquid NaHSO₄ and the solid Na₂ SO₄ at a temperature above 370 ⁰F may be represented by the equation log[SO₃]=0.009135T-2.456, where log[SO₃] is the log base 10 of the SO₃ concentration in ppm and T is the flue gas temperature in ⁰F. Thus, when trona is injected into flue gas at temperatures between about 370° F and about 525 ° F, and at an SO₃ concentration greater than the amount defined by log[SO₃]=0.009135T-2.456, liquid phase NaHSO₄ reaction product is formed.

It has been found that using a sorbent composition comprising mechanically refined trona and an additive minimizes the amount of sticky ash formed in the process. Sodium bicarbonate may be used in place of trona. The additive is selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The additive preferably includes magnesium carbonate, calcium carbonate, or mixtures thereof, and most preferably includes calcium carbonate. The additive is preferably between 0.1% and 5%, most preferably between 0.5% and 2%, by weight of the trona or other sodium sorbent. The sorbent composition is injected into the flue gas stream. The sorbent composition is maintained in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO₃ to reduce the concentration of the SO3 in the flue gas stream. Preferably, formation of a liquid phase NaHSO₄ reaction product is minimized so that little sticky ash is formed. While not intending to be bound by theory, it is believed that the additive reacts with the H2SO4 present in the flue gas stream to remove it thereform, thus minimizing the production of liquid phase NaHSO₄.

Thus, the system may be operated in a range of temperatures and SO3 concentrations where liquid phase NaHSO₄ would form in the absence of the additive. In one embodiment, the temperature of the flue gas where the trona is injected is between about 370° F and about 500° F. The temperature of the flue gas is preferably greater than about 370° F, and more preferably greater than about 385° F. The temperature of the flue gas is preferably less than about 500° F, more preferably less than about 450° F, and most preferably less than about 415° F. The temperature of the flue gas is most preferably between about 385° F and about 415° F. Alternatively, the temperature range can be expressed as a function of the SO3 concentration. Thus, the process may be operated at a temperature and SO3 concentration where log[SO3]>0.009135T-2.456, where [SO3] is the SO3 concentration in ppm and T is the flue gas temperature in ⁰F. The SO3 concentration of the flue gas stream to be treated is generally at least about 3 ppm, and commonly between about 10 ppm and about 200 ppm. The desired outlet SO3 concentration of the gas stack is preferably less than about 50 ppm, more preferably less than about 20 ppm, more preferably less than about 10 ppm, and most preferably less than about 5 ppm. The byproduct of the reaction is collected with fly ash. Trona, like most alkali reagents, will tend to react more rapidly with the stronger acids in the gas stream first, and then after some residence time it will react with the weaker acids. Such gas constituents as HCl and SO3 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as SO₂. Thus, the injected sorbent composition can be used to selectively remove SO3 without substantially decreasing the amount of SO₂ in the flue gas stream.

A schematic of one embodiment of the process is shown in FIG. 2. The furnace or combustor 10 is fed with a fuel source 12, such as coal, and with air 14 to burn the fuel source 12. From the combustor 10, the combustion gases are conducted to a heat exchanger or air heater 30. Ambient air 32 may be injected to lower the flue gas temperature. A selective catalytic reduction (SCR) device 20 may be used to remove NO_x gases. A bypass damper 22 can be opened to bypass the flue gas from the SCR. The outlet of the heat exchanger or air heater 30 is connected to a particulate collection device 50. The particulate collection device 50 removes particles made during the combustion process, such as fly ash, from the flue gas before it is conducted to an optional wet scrubber vessel 54 and then to the gas stack 60 for venting. The particulate collection device 50 may be an electrostatic precipitator (ESP). Other types of particulate collection devices, such as a baghouse, may also be used for solids removal. The baghouse contains filters for separating particles made during the combustion process from the flue gas.

The SO₃ removal system includes a source of sorbent composition 40. The sorbent composition includes an additive and a sodium sorbent such as trona or sodium bicarbonate. The sodium sorbent is preferably trona. The trona is preferably provided as particles with a mean particle size between about 10 micron and about 40 micron, most preferably between about 24 micron and about 28 micron. The mean particle size of the additive may be generally about the same size as the trona and is preferably between about 10 micron and about 25 micron. The sorbent composition is preferably in a dry granular form.

A suitable trona source is T-200® trona, which is a mechanically refined trona ore product available from Solvay Chemicals. T-200® trona contains about 97.5% sodium sesquicarbonate and has a mean particle size of about 24-28 micron. The system may also include a ball mill pulverizer, or other type of mill, for decreasing and/or otherwise controlling the particle size of the trona or other sorbent compositions. It has also been found that the additive may improve the flow properties of the trona when added thereto. A method of delivering a dry sorbent for flue gas injection includes combining the additive and trona to form a sorbent composition. The additive may be magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof. The sorbent composition is transported in a vessel to the location of a flue gas injection. The sorbent composition is offloaded out of the vessel and injected into the flue gas stream, wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.

The sorbent composition is conveyed from the sorbent composition source 40 to the injector 42. The sorbent composition may be conveyed pneumatically or by any other suitable method. As shown in FIG. 2, the injection apparatus 42 introduces the sorbent composition into flue gas duct section 44, which is disposed at a position upstream of the baghouse inlet and preferably downstream of the heat exchanger outlet. The injection system is preferably designed to maximize contact of the sorbent composition with the SO₃ in the flue gas stream. Any type of injection apparatus known in the art may be used to introduce the sorbent composition into the gas duct. For example, injection can be accomplished directly by a compressed air-driven eductor.

The process requires no slurry equipment or reactor vessel if the sorbent composition is stored and injected dry into the flue duct 44 where it reacts with the acid gas. However, the process may also be used with humidification of the flue gas or wet injection of the sorbent composition. Additionally, the particulates can be collected wet through a wet scrubber vessel 54 should the process be used for trim scrubbing of acid mist. In particular, the flue gas desulfurization system may be operated so that the SO₃ removal is accomplished by injecting the sorbent composition into the flue gas, while the majority of the SO₂ is removed by the wet scrubber 54.

The process may also be varied to control the flue gas temperature. For example, the flue gas temperature upstream of the trona or other sodium sorbent may be adjusted to obtain the desired flue gas temperature where the sorbent composition is injected. Additionally, ambient air 32 may be introduced into the flue gas stream to lower the flue gas temperature and the flue gas temperature monitored where the sorbent composition is injected. Other possible methods of controlling the flue gas temperature include using heat exchanges and/or air coolers. The process may also vary the trona injection location or include multiple locations for sorbent composition injection.

For the achievement of desulfurization, the sorbent composition is preferably injected at a rate with respect to the flow rate of the SO3 to provide a normalized stoichiometric ratio (NSR) of sodium to sulfur of about 1.0 or greater. The NSR is a measure of the amount of reagent injected relative to the amount theoretically required. The NSR expresses the stoichiometric amount of sorbent required to react with all of the acid gas. For example, an NSR of 1.0 would mean that enough material was injected to theoretically yield 100 percent removal of the SO3 in the inlet flue gas; an NSR of 0.5 would theoretically yield 50 percent SO₃ removal. The reaction of SO₃ with the sodium carbonate is very fast and efficient, so that a NSR of only about one is generally required for SO₃ removal. The sorbent composition preferentially reacts with SO₃ over SO₂, so SO₃ will be removed even if large amounts of SO₂ are present. Preferably, an NSR of less than 2.0 or more preferably less than 1.5 is used such that there is no substantial reduction of the SO₂ concentration in the flue gas caused by reaction with excess sorbent. Because NO_x removal systems tend to oxidize existing SO₂ into SO₃, the injection system may also be combined with an NO_x removal system. The trona injection system may also be combined with other SO_x removal systems, such as sodium bicarbonate, lime, limestone, etc. in order to enhance performance or remove additional hazardous gases such as HCl, NO_x, and the like. An electric generation plant uses a hot side electrostatic precipitator (ESP) and no baghouse. The plant uses a catalyst for NO_x removal, which causes elevated SO₃ levels in the flue gas. The SO₃ concentration in the flue gas is between about 100 ppm and about 125 ppm. T-200® trona from Solvay Chemicals is injected to remove SO₃ from the flue gas. As a comparative example, trona is injected at a temperature of 400° F with no additive at NSR values of about 1.5. The perforated plates of the ESP in the plant exhibit significant solids buildup which requires frequent cleaning. A sorbent composition comprising trona and 1% calcium carbonate is injected into flue gas at a temperature of 400° F at NSR values of about 1.5. A perforated plate of an ESP in the plant after operation of the SO₃ removal system is relatively free of solids buildup.

According to the present invention, using an additive reduces the amount of sticky waste products in the SO₃ removal process, compared to a process using trona without an additive under the same processing conditions. The embodiments described above and shown herein are illustrative and not restrictive. The scope of the invention is indicated by the claims rather than by the foregoing description and attached drawings. The invention may be embodied in other specific forms without departing from the spirit of the invention. Accordingly, these and any other changes which come within the scope of the claims are intended to be embraced therein.

Claims

C L A I M S

1. A method of removing SO₃ from a flue gas stream having increased amounts of SO3 formed by a NO_x removal system, the method comprising injecting into the flue gas stream a sorbent composition comprising a sodium sorbent and an additive to reduce the concentration of the SO3 in the flue gas stream and minimize the formation of a liquid phase NaHSO₄ reaction product, wherein the sodium sorbent is selected from the group consisting of mechanically refined trona, sodium bicarbonate, and mixtures thereof, and the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof.

2. The method of claim 1 wherein the temperature of the flue gas is between 370° F and 500° F.

3. The method of claim 1 wherein the temperature of the flue gas is between 385° F and 450° F.

4. The method of claim 1 wherein the additive is between 0.1% and 5% by weight of the trona.

5. The method of claim 1 wherein the additive is between 0.5% and 2% by weight of the trona.

6. The method of claim 1 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.

7. The method of claim 1 wherein the additive comprises calcium carbonate.

8. The method of claim 1 wherein the flue gas stream comprises at least 3 ppm SO₃ upstream of the location where the sorbent composition is injected.

9. The method of claim 20 wherein the flue gas stream comprises between 10 ppm and 200 ppm SO₃ upstream of the location where the sorbent composition is injected.

10. The method of claim 1 wherein the sodium sorbent comprises trona with a mean particle size less than 40 micron.

11. The method of claim 1 wherein the sodium sorbent comprises trona with a mean particle size between 24 micron and 28 micron.

12. The method of claim 1 wherein the sorbent composition is injected as a dry material.

13. The method of claim 1 wherein the SO₃ concentration is greater than an amount according to the equation log[SC>3]>0.009135T-2.456, where T is the flue gas temperature in ° F and SO3 is the concentration in ppm.

14. A method of removing SO₃ from a flue gas stream having increased amounts of SO3 formed by a NO_x removal system, the method comprising:

• providing a sorbent composition comprising mechanically refined trona and an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof;

• injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is greater than 370° F and less than 450° F; and

• maintaining the sorbent composition in contact with the flue gas for a time sufficient to react a portion of the sorbent composition with a portion of the SO3 to reduce the concentration of the SO3 in the flue gas stream and minimize the formation of a liquid phase NaHSO₄ reaction product.

15. The method of claim 14 wherein the additive is between 0.1% and

5% by weight of the trona.

16. The method of claim 14 wherein the additive is between 0.5% and 2% by weight of the trona.

17. The method of claim 14 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.

18. The method of claim 14 wherein the additive comprises calcium carbonate.

19. The method of claim 14 wherein the mean particle size of the additive is between 20 micron and 25 micron.

20. The method of claim 14 wherein the flue gas stream comprises at least 3 ppm SO₃ upstream of the location where the sorbent composition is injected.

21. The method of claim 14 wherein the flue gas stream comprises between 10 ppm and 200 ppm SO₃ upstream of the location where the sorbent composition is injected.

22. The method of claim 14 wherein the SO₃ concentration is greater than an amount according to the equation log[SC>3]>0.009135T-2.456, where T is the flue gas temperature in ° F and SO3 is the concentration in ppm.

23. The method of claim 14 wherein the mean particle size of trona is between 10 micron and 40 micron.

24. The method of claim 14 wherein the temperature of the flue gas is between 385° F and 415° F.

25. The method of claim 14 wherein the sorbent composition is injected at a rate with respect to the flow rate of the SO3 to provide a normalized stoichiometric ratio of sodium to sulfur of between 1.0 and 1.5.

26. The method of claim 14 wherein the sorbent composition is injected as a dry material.

27. The method of claim 14 further comprising combining the additive with the trona before delivery of the sorbent composition to the site of the flue gas stream.

28. A method of removing SO₃ from a flue gas stream comprising between 3 ppm and 200 ppm SO₃, the method comprising:

• providing a sorbent composition comprising trona and an additive selected from group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof, wherein the additive is between 0.1% and 5% by weight of the trona; and

• injecting the sorbent composition into the flue gas stream, wherein the temperature of the flue gas is between 370° F and 450° F.

29. The method of claim 28 wherein the additive is between 0.5% and 2% by weight of the trona.

30. The method of claim 28 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.

31. The method of claim 28 wherein the mean particle size of trona is between 24 micron and 28 micron.

32. The method of claim 28 wherein the temperature of the flue gas is between 385° F and 415° F.

33. The method of claim 28 wherein the SO₃ concentration is greater than an amount according to the equation log[SC>3]>0.009135T-2.456, where T is the flue gas temperature in ° F and SO3 is the concentration in ppm.

34. A method of delivering a dry sorbent for flue gas injection comprising: • providing trona;

• combining with the trona an additive selected from the group consisting of magnesium carbonate, calcium carbonate, magnesium hydroxide, calcium hydroxide, and mixtures thereof to form a sorbent composition;

• transporting the sorbent composition in a vessel to the location of a flue gas injection;

• offloading the sorbent composition out of the vessel and injecting the sorbent composition into the flue gas stream wherein sufficient amounts of additive are combined with the trona to enhance the flowability of the sorbent composition out of the vessel.

35. The method of claim 34 wherein the additive is between 0.1% and 5% by weight of the trona.

36. The method of claim 34 wherein the additive is between 0.5% and 2% by weight of the trona.

37. The method of claim 34 wherein the additive is selected from the group consisting of magnesium carbonate, calcium carbonate, and mixtures thereof.

38. The method of claim 34 wherein the additive comprises calcium carbonate.

39. The method of claim 34 wherein the mean particle size of the trona is less than 40 micron.

40. The method of claim 34 wherein the mean particle size of the trona is between 24 micron and 28 micron.

41. The method of claim 34 wherein the mean particle size of the additive is between 20 micron and 25 micron.